Control of resin curing

ABSTRACT

Systems and methods of treating a zone of a subterranean formation penetrated by a wellbore are described. A composition may include a first solution including at least one amine containing resin; and citraconic anhydride. The composition may also include a second solution mixed with the first solution, where the second solution includes at least one epoxide containing resin. Methods may include providing the treatment fluid to a subterranean formation.

FIELD

The disclosure generally relates to producing oil or gas from a subterranean formation. More specifically, the disclosure relates to compositions and methods for use in treating a subterranean formation for controlling the migration of particulates, such as formation sand and fines.

BACKGROUND

Oil or gas is obtained from a subterranean formation by drilling a wellbore that penetrates a hydrocarbon-bearing formation. It is desirable to maximize both the rate of flow and the overall amount of flow of hydrocarbon from the subterranean formation to the surface.

One way that the rate of hydrocarbon flow and the overall amount of hydrocarbon flow can be reduced is by fines production or sand migration in the formation or by precipitation. The relatively high velocity in the permeable matrix of the subterranean formation near the wellbore is sometimes sufficient to mobilize particulates. These particulates can be carried and then plug flow channels in the formation, a proppant pack, or a gravel pack. It is desirable to minimize fines or sand migration, since such particulates block flow paths, choking the potential production of the well. In addition, such particulates can damage downhole and surface equipment, such as screens, pumps, flow lines, storage facilities, etc.

Wellbores often penetrate subterranean formations that contain unconsolidated particulates that may migrate when oil, gas, water, or other fluids are produced or flowed back from the subterranean formation.

Devices such as screens and slotted liners are often used to provide support for these unconsolidated formations to inhibit formation collapse. Usually, the annulus around the support device is gravel packed to reduce the presence of voids between the device and the borehole. Typically, such gravel packing operations involve the pumping and placement of a quantity of a desired size of particulate material into the annulus between the tubular device and the borehole of the wellbore. Gravel packing forms a filtration bed near the wellbore that acts as a physical barrier to the transport of unconsolidated formation fines with the production of hydrocarbons. These support devices provide support for the wellbore and gravel packing and prevent some fines from entering the hydrocarbon flow into the well.

Some types of screens are adapted to be expanded to contact the wellbore wall either with or without gravel packing. It is, however, impossible to eliminate all voids between the screen and the wellbore wall. Fines fill these voids blocking flow and in some instances fines flowing through these voids erode the screen, destroying its effectiveness.

One common type of gravel packing operation involves placing a gravel pack screen in the wellbore and packing the surrounding annulus between the screen and the wellbore with gravel of a specific mesh size designed to prevent the passage of formation sand or fines. The gravel pack screen is generally a filter assembly used to retain the gravel placed during a gravel pack operation. A wide range of sizes and screen configurations are available to suit the characteristics of the gravel pack sand. Similarly, a wide range of gravel sizes is available to suit the characteristics of the unconsolidated or poorly consolidated particulates in the subterranean formation. The resulting structure presents a barrier to migrating sand from the formation while still permitting fluid flow.

Gravel packs can be time consuming and expensive to install. Due to the time and expense needed, it is sometimes desirable to place a screen without the gravel and, particularly in cases in which an expandable screen is being placed, it may be unrealistic to place a bed of gravel between the expandable screen and the wellbore. Even in circumstances in which it is practical to place a screen without a gravel pack, it is often difficult to determine an appropriate screen size to use as formation sands tend to have a wide distribution of sand grain sizes. When small quantities of sand are allowed to flow through a screen, screen erosion becomes a significant concern. As a result, the placement of gravel as well as the screen is often necessary to control the formation sands.

An expandable screen is often installed to maintain the diameter of the wellbore for ease of access at a later time by eliminating installation of conventional screens, gravel placement, and other equipment. However, the ability to provide universal screen mesh that can handle wide particle size distribution of formation sand is unrealistic, if not impossible.

Another method used to control particulates in unconsolidated formations involves consolidating a subterranean producing zone into hard, permeable masses. Consolidation of a subterranean formation zone often involves applying a resin followed by a spacer fluid and then a catalyst. Such resin application may be problematic when, for example, an insufficient amount of spacer fluid is used between the application of the resin and the application of the external catalyst. The resin may come into contact with the external catalyst in the wellbore itself rather than in the unconsolidated subterranean producing zone. When resin is contacted with an external catalyst, an exothermic reaction occurs that may result in rapid polymerization, potentially damaging the formation by plugging the pore channels, halting pumping when the wellbore is plugged with solid material, or resulting in a downhole explosion as a result of the heat of polymerization. Also, these conventional processes are not practical to treat long intervals of unconsolidated regions due to the difficulty in determining whether the entire interval has been successfully treated with both the resin and the external catalyst. Gravel packing is a costly operation and resin placement can sometimes damage the formation.

As indicated, a variety of chemical treatments are available for controlling fines migration. Resin treatments are widely accepted. Resin systems, however, fail to achieve deep penetration due to high viscosity and premature curing. The major cause behind the premature curing in majority of resin systems is the immediate temperature sensitive crosslinking reaction between epoxy and amine groups.

In addition to the unconsolidated formation sands often found in subterranean formations, particulate materials are often introduced into subterranean zones in conjunction with conductivity enhancing operations and sand control operations. Conductivity enhancing and sand control operations may be performed as individual treatments, or may be combined where desired.

Preventing formation sand and fines from migrating from an unconsolidated formation has always been a challenge. While previously known treatment methods for unconsolidated formation provide improved particulate control, multiple treatment steps that are time consuming and expensive are usually required. Therefore, it is desirable to develop relatively simple and relatively inexpensive treatment compositions and methods to improve or maintain the rate of fluid flow while reducing particulate migration.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are included to provide a further understanding of the disclosure and are incorporated in and constitute a part of this specification, illustrate preferred embodiments of the disclosure and together with the detailed description serve to explain the principles of the disclosure. In the drawings:

FIG. 1 is a diagram illustrating an example of a fracturing system that may be used in accordance with certain embodiments of the present disclosure.

FIG. 2 is a diagram illustrating an example of a subterranean formation in which a fracturing operation may be performed in accordance with certain embodiments of the present disclosure.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Systems and methods are described for resin curing control in treatment of a subterranean formation. In certain embodiments, a chemical component may delay crosslinking reaction between amine and epoxy groups in a treatment fluid. Certain embodiments may include an amine containing resin, an epoxide containing resin and citraconic anhydride. Embodiments may improve penetration into a formation. The systems and methods described herein may be applied in oilfield drilling applications or for other situations where uses of resin materials, in or out of a wellbore, are advantageous. The examples described herein relate to resin treatments for illustrative purposes only. In alternate embodiments, the systems and methods may be used wherever use of resin is desirable.

DEFINITIONS AND USAGES

General Interpretation

The words or terms used herein have their plain, ordinary meaning in the field of this disclosure, except to the extent explicitly and clearly defined in this disclosure or unless the specific context otherwise requires a different meaning.

If there is any conflict in the usages of a word or term in this disclosure and one or more patent(s) or other documents that may be incorporated by reference, the definitions that are consistent with this specification should be adopted.

The words “comprising,” “containing,” “including,” “having,” and all grammatical variations thereof are intended to have an open, non-limiting meaning. For example, a composition comprising a component does not exclude it from having additional components, an apparatus comprising a part does not exclude it from having additional parts, and a method having a step does not exclude it having additional steps. When such terms are used, the compositions, apparatuses, and methods that “consist essentially of” or “consist of” the specified components, parts, and steps are specifically included and disclosed.

The indefinite articles “a” or “an” mean one or more than one of the component, part, or step that the article introduces.

Whenever a numerical range of degree or measurement with a lower limit and an upper limit is disclosed, any number and any range falling within the range is also intended to be specifically disclosed. For example, every range of values (in the form “from a to b,” or “from about a to about b,” or “from about a to b,” “from approximately a to b,” and any similar expressions, where “a” and “b” represent numerical values of degree or measurement) is to be understood to set forth every number and range encompassed within the broader range of values.

It should be understood that algebraic variables and other scientific symbols used herein are selected arbitrarily or according to convention. Other algebraic variables can be used.

Subterranean Formations and Oil and Gas Reservoirs

In the context of production from a well, “oil” and “gas” are understood to refer to crude oil and natural gas, respectively. Oil and gas are naturally occurring hydrocarbons in certain subterranean formations.

A “subterranean formation” is a body of rock that has sufficiently distinctive characteristics and is sufficiently continuous for geologists to describe, map, and name it.

A subterranean formation having a sufficient porosity and permeability to store and transmit fluids is sometimes referred to as a “reservoir.”

A subterranean formation containing oil or gas may be located under land or under the seabed off shore. Oil and gas reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs) below the surface of the land or seabed.

In geology, rock or stone is a naturally occurring solid aggregate of minerals or mineraloids. The Earth's outer solid layer, the lithosphere, is made of rock. Three major groups of rocks are igneous, sedimentary, and metamorphic. The vast majority of reservoir rocks are sedimentary rocks, but highly fractured igneous and metamorphic rocks can sometimes be reservoirs.

A consolidated formation is a geologic material for which the particles are stratified (layered), cemented, or firmly packed together (hard rock); usually occurring at a depth below the ground surface. An unconsolidated formation is a sediment that is loosely arranged or unstratified (not in layers) or whose particles are not cemented together (soft rock); occurring either at the ground surface or at a depth below the surface. In an unconsolidated or weakly consolidated formation, some particulates are insufficiently bonded in the formation to withstand the forces produced by the production or flowback of fluids through the matrix of the formation.

As used herein, a subterranean formation having greater than about 50% by weight of inorganic siliceous materials (e.g., sandstone) is referred to as a “sandstone formation.”

There are conventional and non-conventional types of reservoirs. In a conventional reservoir, the hydrocarbons flow to the wellbore in a manner that can be characterized by flow through permeable media, where the permeability may or may not have been altered near the wellbore, or flow through permeable media to a permeable (conductive), bi-wing fracture placed in the formation. A conventional reservoir would typically have a permeability greater than about 1 milliDarcy (equivalent to about 1,000 microDarcy).

Wells, Well Servicing, Treatment Fluids, and Treatment Zones

To produce oil or gas from a reservoir, a wellbore is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir. Typically, a wellbore of a well must be drilled hundreds or thousands of feet into the earth to reach a hydrocarbon-bearing formation.

Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a fluid into a well.

A “well” includes a wellhead and at least one wellbore from the wellhead penetrating the earth. The “wellhead” is the surface termination of a wellbore, which surface may be on land or on a seabed.

A “well site” is the geographical location of a wellhead of a well. It may include related facilities, such as a tank battery, separators, compressor stations, heating or other equipment, and fluid pits. If offshore, a well site can include a platform.

The “wellbore” refers to the drilled hole, including any cased or uncased portions of the well or any other tubulars in the well. The “borehole” usually refers to the inside wellbore wall, that is, the rock surface or wall that bounds the drilled hole. A wellbore can have portions that are vertical, horizontal, or anything in between, and it can have portions that are straight, curved, or branched. As used herein, “uphole,” “downhole,” and similar terms are relative to the direction of the wellhead, regardless of whether a wellbore portion is vertical or horizontal.

A wellbore can be used as a production or injection wellbore. A production wellbore is used to produce hydrocarbons from the reservoir. An injection wellbore is used to inject a fluid, e.g., liquid water or steam, to drive oil or gas to a production wellbore.

As used herein, introducing “into a well” means introducing at least into and through the wellhead. According to various techniques known in the art, tubulars, equipment, tools, or fluids can be directed from the wellhead into any desired portion of the wellbore.

As used herein, the term “annulus” means the space between two generally cylindrical objects, one inside the other. The objects can be concentric or eccentric. Without limitation, one of the objects can be a tubular and the other object can be an enclosed conduit. The enclosed conduit can be a wellbore or borehole or it can be another tubular. The following are some non-limiting examples illustrating some situations in which an annulus can exist. Referring to an oil, gas, or water well, in an open hole well, the space between the outside of a tubing string and the borehole of the wellbore is an annulus. In a cased hole, the space between the outside of the casing and the borehole is an annulus. In addition, in a cased hole there may be an annulus between the outside cylindrical portion of a tubular such as a production tubing string and the inside cylindrical portion of the casing. An annulus can be a space through which a fluid can flow or it can be filled with a material or object that blocks fluid flow, such as a packing element. Unless otherwise clear from the context, as used herein an “annulus” is a space through which a fluid can flow.

As used herein, a “fluid” broadly refers to any fluid adapted to be introduced into a well for any purpose. A fluid can be, for example, a drilling fluid, a setting composition, a treatment fluid, or a spacer fluid. If a fluid is to be used in a relatively small volume, for example less than about 200 barrels (about 8,400 US gallons or about 32 m³), it is sometimes referred to as a wash, dump, slug, or pill.

As used herein, the word “treatment” refers to any treatment for changing a condition of a portion of a wellbore, or a subterranean formation adjacent a wellbore; however, the word “treatment” does not necessarily imply any particular treatment purpose. A treatment usually involves introducing a fluid for the treatment, in which case it may be referred to as a treatment fluid, into a well. As used herein, a “treatment fluid” is a fluid used in a treatment. The word “treatment” in the term “treatment fluid” does not necessarily imply any particular treatment or action by the fluid.

A “zone” refers to an interval of rock along a wellbore that is differentiated from uphole and downhole zones based on hydrocarbon content or other features, such as permeability, composition, perforations or other fluid communication with the wellbore, faults, or fractures. A zone of a wellbore that penetrates a hydrocarbon-bearing zone that is capable of producing hydrocarbon is referred to as a “production zone.” A “treatment zone” refers to an interval of rock along a wellbore into which a fluid is directed to flow from the wellbore. As used herein, “into a treatment zone” means into and through the wellhead and, additionally, through the wellbore and into the treatment zone.

The term “damage” as used herein regarding a subterranean formation refers to undesirable deposits in a subterranean formation that may reduce its permeability. Scale, skin, gel residue, hydrates, and resin damage, are contemplated by this term.

The term “sand control device” is used generically herein and is meant to include and cover all types of similar structures which are commonly used in gravel pack well completions which permit flow of fluids through the “screen” while blocking the flow of particulates (e.g., commercially-available screens; slotted or perforated liners or pipes; sintered-metal screens; sintered-sized, mesh screens; screened pipes; pre-packed screens, radially-expandable screens or liners; or combinations thereof).

Generally, the greater the depth of the formation, the higher the static temperature and pressure of the formation. Initially, the static pressure equals the initial pressure in the formation before production. After production begins, the static pressure approaches the average reservoir pressure.

Deviated wells are wellbores inclined at various angles to the vertical. Complex wells include inclined wellbores in high-temperature or high-pressure downhole conditions.

A “design” refers to the estimate or measure of one or more parameters planned or expected for a particular fluid or stage of a well service or treatment. For example, a fluid can be designed to have components that provide a minimum density or viscosity for at least a specified time under expected downhole conditions. A well service may include design parameters such as fluid volume to be pumped, required pumping time for a treatment, or the shear conditions of the pumping.

The term “design temperature” refers to an estimate or measurement of the actual temperature at the downhole environment during the time of a treatment. For example, the design temperature for a well treatment takes into account not only the bottom hole static temperature (“BHST”), but also the effect of the temperature of the fluid on the BHST during treatment. The design temperature for a fluid or treatment is sometimes referred to as the bottom hole circulation temperature (“BHCT”). Because fluids may be considerably cooler than BHST, the difference between the two temperatures can be quite large. Ultimately, if left undisturbed a subterranean formation will return to the BHST.

Phases and Physical States

As used herein, “phase” is used to refer to a substance having a chemical composition and physical state that is distinguishable from an adjacent phase of a substance having a different chemical composition or a different physical state.

As used herein, if not other otherwise specifically stated, the physical state or phase of a substance (or mixture of substances) and other physical properties are determined at a temperature of 77° F. (25° C.) and a pressure of 1 atmosphere (Standard Laboratory Conditions) without applied shear.

Particles and Particulates

As used herein, a “particle” refers to a body having a finite mass and sufficient cohesion such that it can be considered as an entity but having relatively small dimensions. A particle can be of any size ranging from molecular scale to macroscopic, depending on context.

A particle can be in any physical state. For example, a particle of a substance in a solid state can be as small as a few molecules on the scale of nanometers up to a large particle on the scale of a few millimeters, such as large grains of sand. Similarly, a particle of a substance in a liquid state can be as small as a few molecules on the scale of nanometers up to a large drop on the scale of a few millimeters. A particle of a substance in a gas state is a single atom or molecule that is separated from other atoms or molecules such that intermolecular attractions have relatively little effect on their respective motions.

As used herein, particulate or particulate material refers to matter in the physical form of distinct particles in a solid or liquid state (which means such an association of a few atoms or molecules). As used herein, a particulate is a grouping of particles having similar chemical composition and particle size ranges anywhere in the range of about 0.5 micrometer (500 nm), e.g., microscopic clay particles, to about 3 millimeters, e.g., large grains of sand.

A particulate can be of solid or liquid particles. As used herein, however, unless the context otherwise requires, particulate refers to a solid particulate. Of course, a solid particulate is a particulate of particles that are in the solid physical state, that is, the constituent atoms, ions, or molecules are sufficiently restricted in their relative movement to result in a fixed shape for each of the particles.

It should be understood that the terms “particle” and “particulate,” includes all known shapes of particles including substantially rounded, spherical, oblong, ellipsoid, rod-like, fiber, polyhedral (such as cubic materials), etc., and mixtures thereof. For example, the term “particulate” as used herein is intended to include solid particles having the physical shape of platelets, shavings, flakes, ribbons, rods, strips, spheroids, toroids, pellets, tablets or any other physical shape.

A particulate will have a particle size distribution (“PSD”). As used herein, “the size” of a particulate can be determined by methods known to persons skilled in the art.

One way to measure the approximate particle size distribution of a solid particulate is with graded screens. A solid particulate material will pass through some specific mesh (that is, have a maximum size; larger pieces will not fit through this mesh) but will be retained by some specific tighter mesh (that is, a minimum size; pieces smaller than this will pass through the mesh). This type of description establishes a range of particle sizes. A “+” before the mesh size indicates the particles are retained by the sieve, while a “−” before the mesh size indicates the particles pass through the sieve. For example, −70/+140 means that 90% or more of the particles will have mesh sizes between the two values.

Particulate materials are sometimes described by a single mesh size, for example, 100 U.S. Standard mesh. If not otherwise stated, a reference to a single particle size means about the mid-point of the industry-accepted mesh size range for the particulate.

Particulates smaller than about 400 U.S. Standard Mesh are usually measured or separated according to other methods because small forces such as electrostatic forces can interfere with separating tiny particulate sizes using a wire mesh.

The most commonly-used grade scale for classifying the diameters of sediments in geology is the Udden-Wentworth scale. According to this scale, a solid particulate having particles smaller than 2 mm in diameter is classified as sand, silt, or clay. Sand is a detrital grain between 2 mm (equivalent to 2,000 micrometers) and 0.0625 mm (equivalent to 62.5 micrometers) in diameter. (Sand is also a term sometimes used to refer to quartz grains or for sandstone.) Silt refers to particulate between 74 micrometers (equivalent to about −200 U.S. Standard mesh) and about 2 micrometers. Clay is a particulate smaller than 0.0039 mm (equivalent to 3.9 μm).

As used herein, “fines” refers to solid particulates that are smaller than most sand particulates, and generally less than about 50 micrometers.

Fluids

A fluid can be a homogeneous or heterogeneous. In general, a fluid is an amorphous substance that is or has a continuous phase of particles that are smaller than about 1 micrometer that tends to flow and to conform to the outline of its container.

Every fluid inherently has at least a continuous phase. A fluid can have more than one phase. The continuous phase of a treatment fluid is a liquid under Standard Laboratory Conditions. For example, a fluid can be in the form of a suspension (larger solid particles dispersed in a liquid phase), a sol (smaller solid particles dispersed in a liquid phase), an emulsion (liquid particles dispersed in another liquid phase), or a foam (a gas phase dispersed in a liquid phase).

An “oil-based” fluid means that oil is the dominant material by weight of the continuous phase of the fluid. In this context, the oil of an oil-based fluid can be any oil.

In the context of a fluid, oil is understood to refer to any kind of oil in a liquid state, whereas gas is understood to refer to a physical state of a substance, in contrast to a liquid. In this context, an oil is any substance that is liquid under Standard Laboratory Conditions, is hydrophobic, and soluble in organic solvents. Oils typically have a high carbon and hydrogen content and are non-polar substances. This general definition includes classes such as petrochemical oils, vegetable oils, and many organic solvents. All oils, even synthetic oils, can be traced back to organic sources.

Solubility

The term “solution” is intended to include not only true molecular solutions but also dispersions of a polymer wherein the polymer is so highly hydrated as to cause the dispersion to be visually clear and having essentially no particulate matter visible to the unaided eye. The term “soluble” is intended to have a meaning consistent with these meanings of solution.

As used herein, a substance is considered to be “soluble” in a liquid if at least 1 grams of the substance can be hydrated or dissolved in one liter of the liquid when tested at 77° F. and 1 atmosphere pressure for 2 hours, considered to be “insoluble” if less than 1 gram per liter, and considered to be “sparingly soluble” for intermediate solubility values.

As will be appreciated by a person of skill in the art, the hydratability, dispersibility, or solubility of a substance in water can be dependent on the salinity, pH, or other substances in the water. Accordingly, the salinity, pH, and additive selection of the water can be modified to facilitate the hydratability, dispersibility, or solubility of a substance in aqueous solution. To the extent not specified, the hydratability, dispersibility, or solubility of a substance in water is determined in deionized water, at neutral pH, and without any other additives.

Apparent Viscosity of a Fluid

Viscosity is a measure of the resistance of a fluid to flow. In everyday terms, viscosity is “thickness” or “internal friction.” Therefore, pure water is “thin,” having a relatively low viscosity whereas honey is “thick,” having a relatively higher viscosity. Put simply, the less viscous the fluid is, the greater its ease of movement (fluidity). More precisely, viscosity is defined as the ratio of shear stress to shear rate.

A Newtonian fluid (named after Isaac Newton) is a fluid for which stress versus strain rate curve is linear and passes through the origin. The constant of proportionality is known as the viscosity. Examples of Newtonian fluids include water and most gases. Newton's law of viscosity is an approximation that holds for some substances but not others.

Non-Newtonian fluids exhibit a more complicated relationship between shear stress and velocity gradient (i.e., shear rate) than simple linearity. Therefore, there exist a number of forms of non-Newtonian fluids. Shear thickening fluids have an apparent viscosity that increases with increasing the rate of shear. Shear thinning fluids have a viscosity that decreases with increasing rate of shear. Thixotropic fluids become less viscous over time at a constant shear rate. Rheopectic fluids become more viscous over time at a constant shear rate. A Bingham plastic is a material that behaves as a solid at low stresses but flows as a viscous fluid at high yield stresses.

Most fluids are non-Newtonian fluids. Accordingly, the apparent viscosity of a fluid applies only under a particular set of conditions including shear stress versus shear rate, which must be specified or understood from the context. As used herein, a reference to viscosity is actually a reference to an apparent viscosity. Apparent viscosity is commonly expressed in units of mP·s or centipoise (cP), which are equivalent.

Like other physical properties, the viscosity of a Newtonian fluid or the apparent viscosity of a non-Newtonian fluid may be highly dependent on the physical conditions, primarily temperature and pressure.

Viscosity Measurements

There are numerous ways of measuring and modeling viscous properties, and new developments continue to be made. The methods depend on the type of fluid for which viscosity is being measured. A typical method for quality assurance or quality control (QA/QC) purposes uses a couette device, such as a FANN™ Model 35 or Model 50 viscometer or a CHANDLER™ Model 5550 HPHT viscometer. Such a viscometer measures viscosity as a function of time, temperature, and shear rate. The viscosity-measuring instrument can be calibrated using standard viscosity silicone oils or other standard viscosity fluids.

Due to the geometry of most common viscosity-measuring devices, however, solid particulate, especially if larger than silt (larger than 74 micron), would interfere with the measurement on some types of measuring devices. Therefore, the viscosity of a fluid containing such solid particulate is usually inferred and estimated by measuring the viscosity of a test fluid that is similar to the fracturing fluid without any proppant or gravel that would otherwise be included. However, as suspended particles (which can be solid, gel, liquid, or gaseous bubbles) usually affect the viscosity of a fluid, the actual viscosity of a suspension is usually somewhat different from that of the continuous phase.

In general, a FANN™ Model 35 viscometer is used for viscosity measurements of less than about 30 mP·s (cP). The Model 35 does not have temperature and pressure controls, so it is used for fluids at ambient conditions (that is, Standard Laboratory Conditions). However, with an optional heating cup, viscosity can be measured at higher temperatures so long as the temperature is below the boiling point of the solvent. Except to the extent otherwise specified, the apparent viscosity of a fluid having a viscosity of less than about 30 cP (excluding any suspended solid particulate larger than silt) is measured with a FANN™ Model 35 type viscometer with a bob and cup geometry using an R1 rotor, B1 bob, and F1 torsion spring at a shear rate of 511 sec⁻¹ (300 rpm) and at a temperature of 77° F. (25° C.) and a pressure of 1 atmosphere.

Permeability

Permeability refers to how easily fluids can flow through a material. For example, if the permeability is high, then fluids will flow more easily and more quickly through the material. If the permeability is low, then fluids will flow less easily and more slowly through the material. As used herein, unless otherwise specified, permeability is measured with light oil having an API gravity of greater than 31.1 degrees.

For gas wells, “high permeability” means the matrix of a subterranean formation has a permeability of at least 10 millidarcy (mD) and “low permeability” means the matrix has a permeability of less than 1 mD. For oil wells, “high permeability” means the matrix of a subterranean formation has a permeability of at least 30 mD and “low permeability” means the matrix has a permeability of less than 10 mD. For gravel packing, “high permeability” means the matrix of a subterranean formation has a permeability of at least 500 mD and “low permeability” means the matrix has a permeability of less than 50 mD.

General Approach

A composition for treating a zone of a subterranean formation penetrated by a wellbore may include various components. In certain embodiments, the treatment fluid may include a combined first solution and second solution.

The first solution may include at least one amine containing resin. In various embodiments, the at least one amine containing resin may be selected from: primary, secondary, tertiary amines, and combinations thereof. In certain embodiments, the at least one amine containing resin may include a silane-based amine in which the silicon atom has only one amine functionality and at least one alkoxy group attached to the silicon atom. The alkoxy group on the silicon atom may assist with the molecule attaching to a surface of a fine/sand. Without being limited by an particular theory, it is believed that an amine functionality on a first chemical may bond with an epoxy group on a second chemical and the other side of the first chemical may form a bond with a fine/sand surface. For example, the at least one amine containing resin may be selected from: aliphatic amines, cycloaliphatic amines, heterocyclic amines, amidoamines, and combinations thereof. In various embodiments, the at least one amine containing resin may be selected from: triethylenetetraamine, ethylenediamine, N-cocoalkyltrimethylenediamine, isophoronediamine, and combinations thereof. In certain embodiments, the at least one amine containing resin may be selected from: trimethoxy silyl propyl ethelene diamine, N-[3 (trimethoxysilyl)propyl]ethylenediamine], 3-aminopropyltriethoxysilane, 3-aminopropyltrimethoxysilane, 4-aminobutyltriethoxysilane, aminophenyltrimehtoxysilane, 3-aminopropyltris(methoxyethoxy-ethoxy)silane, 11-aminodecyltriethoxysilane, 2-(4-pyridylethyl)triethoxysilane, 3-aminopropyl diisopropylethoxysilane, 3-aminopropyl dimethylethoxysilane, N-(2-aminoethyl)-3-aminopropyl-triethoxysilane, N-(6-aminohexyl)aminomethyl-triethoxysilane, N-(6-aminohexyl)aminopropyl-trimethoxysilane, (3 trimethoxysilylpropyl)diethylene triamine, n butylaminopropyltrimethoxysilane, bis(2 hydroxyethyl)-3-aminopropyl-triethoxysilane, 3 (N styrylmethyl-2-aminoethylamino)propyltrimethoxysilane hydrochloride, and combinations thereof.

The at least one amine containing resin, such as a silane-based amine, may not have any other type of functional group that would be subject to rapid hydrolysis or free-radical polymerization under the design conditions, which would make the molecule excessively reactive during placement. In certain embodiments, the at least one amine containing resin may have a concentration of approximately 1% to approximately 3% v/v of the continuous phase of the treatment fluid.

The second solution may include at least one epoxide containing resin. Selection of a suitable epoxide containing resin may be affected by the temperature of the subterranean formation to which the fluid will be introduced. In certain embodiments, the second chemical may have only one epoxy group to avoid polymerization and formation of an epoxy resin. In certain embodiments, the second chemical may be a silane-based compound with only one epoxy group on silicon atom and a minimum of one alkoxy group on silicon atom. Without being limited by any particular theory, it is believed that the alkoxy group on the silicon atom may help the molecule to attach the surface of a fine/sand. Examples of epoxide containing resins that can be used include, but are not limited to, glycidoxy propyl trimethoxy silane, (3 glycidoxypropyl)trimethoxysilane, (3 glycidoxypropyl)triethoxysilane, 5,6 epoxyhexyltriethoxysilane, (3 glycidoxypropyl)methyldiethoxysilane, (3 glycidoxypropyl)methyldimethoxysilane, (3 glycidoxypropyl)dimethylethoxysilane, and combinations thereof.

The at least one epoxide containing resin may not have any other type of functional group that would be subject to rapid hydrolysis or free-radical polymerization under the design conditions, which would make the molecule excessively reactive during placement. In certain embodiments, the at least one epoxide containing resin may have a concentration of approximately 2% to approximately 5% v/v of the continuous phase of the treatment fluid.

The first solution may also include citraconic anhydride. Citraconic anhydride (CAS No 616-02-4) is a chemical with the following formula:

Citraconic anhydride may delay a chemical reaction between amine and epoxy by temporarily converting amine to amide. The citraconic anhydride may delay a crosslinking reaction between the at least one amine containing resin and the at least one epoxide containing resin. While not being limited by any particular theory, the citraconic anhydride may protect the amine group of the at least one amine containing resin from reaction with the epoxides of the at least one epoxide containing resin by reversibly converting amine to amide.

Citraconic anhydride may be added to a solution including the at least one amine containing resin to form the first solution. Citraconic anhydride may be added in quantities such that the pH of the first solution is between approximately 8.0 and approximately 9.0. In certain embodiments, the pH of the first solution may be approximately 8.5.

Continuous Phase

In various embodiments, the treatment fluid comprises a continuous phase that is aqueous, and wherein the at least one amine containing resin and the at least one epoxide containing resin are dissolved or dispersed in the continuous phase.

In various embodiments, the treatment fluid may include less than 10% by weight of a resin. In certain embodiments, the treatment fluid includes less than 1% by weight of any resin. Any resin that may be present should not adversely affect the purposes of the treatment fluid or damage the subterranean formation. In certain embodiments, the treatment fluid does not include any resin.

In various embodiments of methods according to the disclosure, the treatment fluid has a viscosity of less than 5 cP measured at a shear rate of 511 sec⁻¹. In various embodiments of methods according to the disclosure, the treatment fluid has a viscosity of approximately 1 cP measured at a shear rate of 511 sec⁻¹.

The methods according to the disclosure can stabilize the formation particulates of sand and fines by agglomerating the particulates in the formation, thereby preventing the fines from migrating. It is believed that the agglomeration does not substantially reduce the permeability of the subterranean formation or damage the subterranean formation.

The term “regain permeability” refers to the percentage of permeability of a portion of a subterranean formation following treatment; that is, it is a percentage of the post-treatment permeability as compared to the pre-treatment permeability. In some embodiments, the methods of the present disclosure are able to achieve a regain permeability of at least about 60%, which is considered a good regain permeability. In some embodiments, the methods of the present disclosure are able to achieve a regain permeability of at least about 85%. In some embodiments, the methods of the present disclosure are able to achieve a regain permeability of at least about 90%. In some embodiments of the present disclosure, the regain permeability is at least about 95%.

The various embodiments of methods of the present disclosure are capable of substantially stabilizing the particulates such that loose or weakly consolidated particulates are prevented from shifting or migrating once the treatment is complete. This is particularly significant in the context of portions of formations where it is desirable to control the particulates without having to use a gravel pack. In such situations, the methods of the present disclosure including the use of a screen or liner (which may be an expandable or traditional screen or a perforated or slotted liner, or any similar device known in the art) can act to control particulates to a sufficiently high degree that a gravel pack becomes unnecessary.

Thus, according to the embodiments of the present disclosure that include the use of both a treatment fluid according to the disclosure and a mechanical sand control device such as a screen or liner, the methods create a stable, permeable region around the wellbore that resists particulate migration. The screen or liner can be used, for example, to provide mechanical support to prevent borehole collapse. Such embodiments may make the use of screen-only or liner-only (no gravel pack) completions functional over a much wider range of formation properties than previously thought possible.

In addition, the methods can be used by applying the consolidation treatment fluid to transform low quality sand into competent proppant materials. Curable resins, agglomerating agents, or surface modification agents may be used to provide a film of coating on the low-quality sand, encapsulating the grains such that fines generated when the grains are crushed as a result of high stress load applied may be locked in place, mitigating their migration within the proppant pack, thus minimizing its permeability damage. See exemplary process below.

In addition, the methods can be used as a remedial treatment to be injected into a treatment zone through a proppant or gravel pack of a previously performed fracturing treatment or gravel pack.

The treatment may first involve the injection of one or more pre-flush fluids to remove hydrocarbons or debris from the surfaces of the formation sand for preconditioning these surfaces for accept the coating of the consolidating treatment fluid. The pre-flush fluid(s) may or may not contain one or more surfactants to enhance the wetting of the consolidating treatment fluid onto the surfaces of the formation sand particulates.

A post-flush fluid may be injected behind the treatment fluid to displace the treatment fluid completely from the wellbore and penetrate a distance (i.e., from 1 to 4 wellbore diameters) into the formations, as well as to displace excess consolidation treatment fluid from the pore spaces between formation sand grains. An aqueous based fluid or a non-aqueous fluid can be used as the post-flush fluid.

After the injection of post-flush fluid, the well may be shut in for a period of time depending on the bottomhole temperature of the well to allow the consolidation treatment fluid to react and transform the formation sand into a permeable, consolidated sand pack.

In another embodiment, rather than a single mixture of the first solution and the second solution, each component may be injected individually.

The injection rate of consolidation treatment is typically maintained less than that of fracture gradient to prevent generation of fracture(s).

The methods can be performed in vertical, inclined, or horizontal wellbores, and in open-hole or under-reamed completions as well as in cased wells. If a method is to be carried out in a cased wellbore, the casing is perforated to provide for fluid communication with a zone of interest in the subterranean formation.

The methods can optionally include the step of: before or after the step of introducing the treatment fluid, introducing a fracturing fluid into the wellbore at a pressure sufficient to create at least one fracture in the subterranean formation. For example, the composition can be used as a prior treatment to hydraulic fracturing.

Treatment Zone

In certain embodiments, the treatment zone is an unconsolidated or weakly consolidated subterranean formation. In certain embodiments, the treatment zone is in a subterranean formation having loose particulate of silicon dioxide such as sand or quartz particles. For example, the subterranean formation can be a sandstone formation. In certain embodiments, the sandstone formation has at least 70% sandstone material by weight. The formation may include some clay, as the siloxane may bond with the surface of a clay, but if clay is present in more than about 5%, the formation may undesirably swell in the presence of water or 3% aqueous KCl.

The subterranean formation can be, for example, a gas reservoir having a permeability greater than about 5 mD. By way of another example, the subterranean formation can be an oil reservoir having a permeability greater than about 20 mD.

Mechanical Sand Control Device

In various embodiments, additionally comprising, before or after introducing the treatment fluid into the zone, installing a mechanical sand control device in the wellbore of the zone.

In certain embodiments, the mechanical sand control device is selected from the group consisting of: a perforated liner, a slotted pipe, a wire-wrapped screen, a non-expandable screen, and an expandable screen.

In certain embodiments, the mechanical sand control device is not gravel packed.

Methods

Certain embodiments may include a method of treating a zone of a subterranean formation penetrated by a wellbore. Methods may include forming a treatment fluid as described herein. The treatment fluid may be introduced through the wellbore into the zone of the subterranean formation surrounding the wellbore.

In certain embodiments, the amide of the treatment fluid may be converted back to amine by lowering the pH in the zone of the subterranean formation. pH may be lowered by in-situ generation of weak acids and/or providing a pH adjusting fluid into the zone of the subterranean formation surrounding the wellbore. In certain embodiments, the pH may be lowered at least to a level that a portion of the amide functionality on the at least one amine containing resin is converted back to an amine functionality. In certain embodiments, the pH may be lowered to approximately 3.0 to approximately 5.0. In certain embodiments, the pH adjusting fluid may be acetic acid, formic acid, one or more buffering agents, and combinations thereof.

Optional Steps

In various embodiments, the methods can optionally or advantageously include additional steps.

For example, the treatment zone and job conditions can be selected such that the design temperature is in the range of about 30° C. to about 200° C.

A method according to the disclosure can include a step of, prior to introducing the treatment fluid: isolating a zone of interest in the subterranean formation.

A treatment fluid can be prepared at the job site.

In certain embodiments, the preparation of a fluid can be done at the job site in a method characterized as being performed “on the fly.” The term “on-the-fly” is used herein to include methods of combining two or more components wherein a flowing stream of one element is continuously introduced into flowing stream of another component so that the streams are combined and mixed while continuing to flow as a single stream as part of the on-going treatment. Such mixing can also be described as “real-time” mixing.

Often the step of delivering a fluid into a well is within a relatively short period after forming the fluid, e.g., less within 30 minutes to one hour. In certain embodiments, the step of delivering the fluid is immediately after the step of forming the fluid, which is “on the fly.”

It should be understood that the step of delivering a treatment fluid into a well can advantageously include the use of one or more fluid pumps.

In an embodiment, the step of introducing is at a rate and pressure below the fracture pressure of the treatment zone. For example, the treatment fluid is introduced to the subterranean formation at a matrix flow rate. That is, the composition is added at such a rate that it is able to penetrate the formation without substantially affecting the structure of the formation sands or proppant or gravel matrixes it encounters.

In an embodiment, the step of introducing a treatment comprises introducing under conditions for fracturing a treatment zone. The fluid is introduced into the treatment zone at a rate and pressure that are at least sufficient to fracture the zone.

The step of introducing the treatment fluid can be performed either before or after the sand screen installation or gravel packing are completed. It is beneficial to provide a method that transforms small formation sand or fines into larger aggregates. In certain embodiments, this does not reduce permeability of the formation, and the permeability may be increased. This enhances the retention of fines behind the screen without plugging or eroding it.

After the step of introducing a treatment, the zone may be shut in. This may occur with time under the temperature, pressure, and other conditions in the zone.

The methods can include a step of: after the steps of shutting in and installing the mechanical sand control device, producing fluid from the subterranean formation through the mechanical sand control device.

In certain embodiments, the step of shutting in is for at least a sufficient time for at least 50% by weight of the amine functionality to react with the epoxide functionality in the treatment zone under the design conditions.

In various embodiments, the methods additionally comprising flowing back or producing from the zone without gravel packing the mechanical sand control device.

In certain embodiments, after any such well treatment, a step of producing hydrocarbon from the subterranean formation is the desirable objective and an additional step according to the method.

EXAMPLE

To facilitate a better understanding of the present disclosure, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the entire scope of the disclosure.

Core flow tests were carried out on a sandpack simulating an unconsolidated subterranean formation to evaluate the effectiveness of treatment with a treatment fluid according to the disclosure.

A treatment fluid was prepared. The treatment fluid included a mixture of:

1. Solution A—Amine containing resin+an amount of citraconic anhydride to create a pH 8.5 for Solution A

2. Solution B—Epoxide containing resin

Test Procedure:

Sandpack was prepared using 88% course silica flour (SSA-2™ available from Halliburton Energy Services, Duncan, Okla.), 10% fluid loss additive (WAC-9™ available from Halliburton Energy Services, Duncan, Okla.), and bentonite clay (2%), with additional layers of 20/40 sand (about 1 cm) at both ends. The fluid loss additive is added to get a non-homogeneity of the sand pack to represent an unconsolidated formation. The two ends of the sandpack were closed using 300 mesh screens and 20/40 mesh. The sandpack was initially saturated with 3% KCl aqueous solution and initial permeability of the sandpack to the 3% KCl solution was determined.

The treatment fluid (Solution A+Solution B) was pumped through the sandpack.

A pH adjusting fluid was pumped through the sandpack.

The sandpack was shut in for 24 to 72 hours at 185° F.

After a predetermined time, final permeability and unconfined compressive strength (UCS) were determined after the curing period. After complete curing the core was extruded from the brass sample cell and cut into a core sample size and then unconfined compressive strength was measured immediately. Good compressive strength was observed.

Observation:

A good regained permeability and unconfined compressive strength was found. Therefore, it was determined that the treatment fluid would not damage a subterranean formation.

CONCLUSION

Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein.

The exemplary methods and compositions disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the disclosed compositions. For example, and with reference to FIG. 1, the disclosed methods and compositions may directly or indirectly affect one or more components or pieces of equipment associated with an exemplary fracturing system 10, according to one or more embodiments. In certain instances, the system 10 includes a fracturing fluid producing apparatus 20, a fluid source 30, a proppant source 40, and a pump and blender system 50 and resides at the surface at a well site where a well 60 is located. In certain instances, the fracturing fluid producing apparatus 20 combines a gel pre-cursor with fluid (e.g., liquid or substantially liquid) from fluid source 30, to produce a hydrated fracturing fluid that is used to fracture the formation. The hydrated fracturing fluid can be a fluid for ready use in a fracture stimulation treatment of the well 60 or a concentrate to which additional fluid is added prior to use in a fracture stimulation of the well 60. In other instances, the fracturing fluid producing apparatus 20 can be omitted and the fracturing fluid sourced directly from the fluid source 30. In certain instances, the fracturing fluid may comprise water, a hydrocarbon fluid, a polymer gel, foam, air, wet gases and/or other fluids.

The proppant source 40 can include a proppant for combination with the fracturing fluid. The system may also include additive source 70 that provides one or more additives (e.g., gelling agents, weighting agents, and/or other optional additives) to alter the properties of the fracturing fluid. For example, the other additives 70 can be included to reduce pumping friction, to reduce or eliminate the fluid's reaction to the geological formation in which the well is formed, to operate as surfactants, and/or to serve other functions.

The pump and blender system 50 receives the fracturing fluid and combines it with other components, including proppant from the proppant source 40 and/or additional fluid from the additives 70. The resulting mixture may be pumped down the well 60 under a pressure sufficient to create or enhance one or more fractures in a subterranean zone, for example, to stimulate production of fluids from the zone. Notably, in certain instances, the fracturing fluid producing apparatus 20, fluid source 30, and/or proppant source 40 may be equipped with one or more metering devices (not shown) to control the flow of fluids, proppants, and/or other compositions to the pumping and blender system 50. Such metering devices may permit the pumping and blender system 50 can source from one, some or all of the different sources at a given time, and may facilitate the preparation of fracturing fluids in accordance with the present disclosure using continuous mixing or “on-the-fly” methods. Thus, for example, the pumping and blender system 50 can provide just fracturing fluid into the well at some times, just proppants at other times, and combinations of those components at yet other times.

FIG. 2 shows the well 60 during a fracturing operation in a portion of a subterranean formation of interest 102 surrounding a well bore 104. The well bore 104 extends from the surface 106, and the fracturing fluid 108 is applied to a portion of the subterranean formation 102 surrounding the horizontal portion of the well bore. Although shown as vertical deviating to horizontal, the well bore 104 may include horizontal, vertical, slant, curved, and other types of well bore geometries and orientations, and the fracturing treatment may be applied to a subterranean zone surrounding any portion of the well bore. The well bore 104 can include a casing 110 that is cemented or otherwise secured to the well bore wall. The well bore 104 can be uncased or include uncased sections. Perforations can be formed in the casing 110 to allow fracturing fluids and/or other materials to flow into the subterranean formation 102. In cased wells, perforations can be formed using shape charges, a perforating gun, hydro jetting and/or other tools.

The well is shown with a work string 112 depending from the surface 106 into the well bore 104. The pump and blender system 50 is coupled a work string 112 to pump the fracturing fluid 108 into the well bore 104. The working string 112 may include coiled tubing, jointed pipe, and/or other structures that allow fluid to flow into the well bore 104. The working string 112 can include flow control devices, bypass valves, ports, and or other tools or well devices that control a flow of fluid from the interior of the working string 112 into the subterranean zone 102. For example, the working string 112 may include ports adjacent the well bore wall to communicate the fracturing fluid 108 directly into the subterranean formation 102, and/or the working string 112 may include ports that are spaced apart from the well bore wall to communicate the fracturing fluid 108 into an annulus in the well bore between the working string 112 and the well bore wall.

The working string 112 and/or the well bore 104 may include one or more sets of packers 114 that seal the annulus between the working string 112 and well bore 104 to define an interval of the well bore 104 into which the fracturing fluid 108 will be pumped. FIG. 2 shows two packers 114, one defining an uphole boundary of the interval and one defining the downhole end of the interval. When the fracturing fluid 108 is introduced into well bore 104 (e.g., in FIG. 2, the area of the well bore 104 between packers 114) at a sufficient hydraulic pressure, one or more fractures 116 may be created in the subterranean zone 102. The proppant particulates in the fracturing fluid 108 may enter the fractures 116 where they may remain after the fracturing fluid flows out of the well bore. These proppant particulates may “prop” fractures 116 such that fluids may flow more freely through the fractures 116.

While not specifically illustrated herein, the disclosed methods and compositions may also directly or indirectly affect any transport or delivery equipment used to convey the compositions to the fracturing system 10 such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the compositions from one location to another, any pumps, compressors, or motors used to drive the compositions into motion, any valves or related joints used to regulate the pressure or flow rate of the compositions, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like.

The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the present disclosure.

The various elements or steps according to the disclosed elements or steps can be combined advantageously or practiced together in various combinations or sub-combinations of elements or sequences of steps to increase the efficiency and benefits that can be obtained from the disclosure.

It will be appreciated that one or more of the above embodiments may be combined with one or more of the other embodiments, unless explicitly stated otherwise.

The illustrative disclosure can be practiced in the absence of any element or step that is not specifically disclosed or claimed.

Furthermore, no limitations are intended to the details of construction, composition, design, or steps herein shown, other than as described in the claims.

All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values.

Although the foregoing description is directed to the preferred embodiments of the disclosure, it is noted that other variations and modifications will be apparent to those skilled in the art, and may be made without departing from the spirit or scope of the disclosure. Moreover, features described in connection with one embodiment of the disclosure may be used in conjunction with other embodiments, even if not explicitly stated above. 

What is claimed is:
 1. A method of treating a zone of a subterranean formation penetrated by a wellbore, the method comprising: (A) forming a treatment fluid comprising: (i) a first solution comprising: (a) at least one amine containing resin; and (b) citraconic anhydride; (ii) a second solution comprising at least one epoxide containing resin; and (B) introducing the treatment fluid through the wellbore into the zone of the subterranean formation surrounding the wellbore.
 2. The method of claim 1, wherein the at least one amine containing resin is selected from the group consisting of: trimethoxy silyl propyl ethelene diamine, N-[3 (trimethoxysilyl)propyl]ethylenediamine], 3-aminopropyltriethoxysilane, 3-aminopropyltrimethoxysilane, 4-aminobutyltriethoxysilane, aminophenyltrimehtoxysilane, 3-aminopropyltris(methoxyethoxy-ethoxy)silane, 11-aminodecyltriethoxysilane, 2-(4-pyridylethyl)triethoxysilane, 3-aminopropyl diisopropylethoxysilane, 3-aminopropyl dimethylethoxysilane, N-(2-aminoethyl)-3-aminopropyl-triethoxysilane, N-(6-aminohexyl)aminomethyl-triethoxysilane, N-(6-aminohexyl)aminopropyl-trimethoxysilane, (3 trimethoxysilylpropyl)diethylene triamine, n butylaminopropyltrimethoxysilane, bis(2 hydroxyethyl)-3-aminopropyl-triethoxysilane, 3 (N styrylmethyl-2-aminoethylamino)propyltrimethoxysilane hydrochloride, and combinations thereof.
 3. The method of claim 2, wherein the at least one amine containing resin is trimethoxy silyl propyl ethelene diamine.
 4. The method of claim 1, wherein the first solution has a pH between approximately 8.0 and approximately 9.0.
 5. The method of claim 4, wherein the first solution has a pH of approximately 8.5.
 6. The method of claim 1, wherein citraconic anhydride is present in the first solution in an amount such that the pH of the first solution has a pH between approximately 8.0 and approximately 9.0.
 7. The method of claim 1, wherein the at least one epoxy containing resin is selected from the group consisting of: glycidoxy propyl trimethoxy silane, (3 glycidoxypropyl)trimethoxysilane, (3 glycidoxypropyl)triethoxysilane, 5,6 epoxyhexyltriethoxysilane, (3 glycidoxypropyl)methyldiethoxysilane, (3 glycidoxypropyl)methyldimethoxysilane, (3 glycidoxypropyl)dimethylethoxysilane, and combinations thereof.
 8. The method of claim 7, wherein the at least one epoxy containing resin is glycidoxy propyl trimethoxy silane.
 9. The method of claim 1, further comprising converting amide in the treatment fluid to amine by lowering pH by in-situ generation of weak acids.
 10. The method of claim 1, further comprising converting amide in the treatment fluid to amine by providing a pH adjusting fluid into the zone of the subterranean formation surrounding the wellbore.
 11. The method of claim 1, further comprising mixing the treatment fluid using mixing equipment.
 12. The method of claim 1, wherein the treatment fluid is introduced into the subterranean formation using one or more pumps.
 13. A composition for treating a zone of a subterranean formation penetrated by a wellbore, the composition comprising: (A) a first solution comprising: (i) at least one amine containing resin; and (ii) citraconic anhydride; (B) a second solution mixed with the first solution, the second solution comprising at least one epoxide containing resin.
 14. The composition of claim 13, wherein the at least one amine containing resin is selected from the group consisting of: trimethoxy silyl propyl ethelene diamine, N-[3 (trimethoxysilyl)propyl]ethylenediamine], 3-aminopropyltriethoxysilane, 3-aminopropyltrimethoxysilane, 4-aminobutyltriethoxysilane, aminophenyltrimehtoxysilane, 3-aminopropyltris(methoxyethoxy-ethoxy)silane, 11-aminodecyltriethoxysilane, 2-(4-pyridylethyl)triethoxysilane, 3-aminopropyl diisopropylethoxysilane, 3-aminopropyl dimethylethoxysilane, N-(2-aminoethyl)-3-aminopropyl-triethoxysilane, N-(6-aminohexyl)aminomethyl-triethoxysilane, N-(6-aminohexyl)aminopropyl-trimethoxysilane, (3 trimethoxysilylpropyl)diethylene triamine, n butylaminopropyltrimethoxysilane, bis(2 hydroxyethyl)-3-aminopropyl-triethoxysilane, 3 (N styrylmethyl-2-aminoethylamino)propyltrimethoxysilane hydrochloride, and combinations thereof.
 15. The composition of claim 14, wherein the at least one amine containing resin is trimethoxy silyl propyl ethelene diamine.
 16. The composition of claim 13, wherein the first solution has a pH between approximately 8.0 and approximately 9.0.
 17. The composition of claim 16, wherein the first solution has a pH of approximately 8.5.
 18. The composition of claim 13, wherein citraconic anhydride is present in the first solution in an amount such that the pH of the first solution has a pH between approximately 8.0 and approximately 9.0.
 19. The composition of claim 13, wherein the at least one epoxy containing resin is selected from the group consisting of: glycidoxy propyl trimethoxy silane, (3 glycidoxypropyl)trimethoxysilane, (3 glycidoxypropyl)triethoxysilane, 5,6 epoxyhexyltriethoxysilane, (3 glycidoxypropyl)methyldiethoxysilane, (3 glycidoxypropyl)methyldimethoxysilane, (3 glycidoxypropyl)dimethylethoxysilane, and combinations thereof.
 20. The composition of claim 19, wherein the at least one epoxy containing resin is glycidoxy propyl trimethoxy silane. 